Abstract Mad Dog is a giant, subsalt, deep-water oil field that will be producing hydrocarbons for the co-owners BP, BHP Billiton Petroleum, and Chevron in the Gulf of Mexico for many years to come. The field was discovered in 1998 by the GC0826#1 well and sidetracks. Four appraisal wells proved up a material resource but also showed evidence of compartmentalization and imperfect subsalt seismic imaging. A spar development was selected and first oil was achieved in 2005. Further appraisal drilling continued from the spar rig and mobile offshore drilling units, ending with the Mad Dog North appraisal program in December 2011. The original spar rig was lost during Hurricane Ike in September, 2008, and a rig replacement project is currently underway. In 2009, the Mad Dog South appraisal well proved up large volumes of hydrocarbons beyond the drilling radius of the original spar rig, necessitating the construction of a second production facility. Mad Dog hydrocarbons are predominantly contained in deep-water turbidite sandstones of early Miocene age that can be correlated over hundreds of square miles. The turbidites are interpreted as a series of individual lobes in a submarine fan complex that was deposited in an unconfined basin floor environment. Deformation of the rocks commenced shortly after deposition and continued through the Plio-Pleistocene boundary. The reservoir is divided into several large compartments that are identified by differences in pressure, fluid composition, and oil-water contacts. These large compartments are interpreted to be bounded by seismically visible faults. Smaller seismically visible and subseismic faults act as baffles to fluid flow in the field, and have been identified through logs, dynamic data, and reservoir simulation. The phased development of the Mad Dog Field has enabled BP and co-owners to mitigate project risk during full-field development. By starting small, developing the known hydrocarbons, investing in technology to improve the imaging of the field, and continuing appraisal drilling, the team was able to evaluate the resources while simultaneously unlocking their value. The integration of dynamic production data with the improved seismic image and appraisal well results has allowed the second phase of the development to proceed with significantly reduced subsurface uncertainty. This has enabled the team to unleash the full potential of the Mad Dog field to be a large deep-water producer for the next 40 years.

Abstract Atlantis Field represents a significant development for BP and co-owner BHP Billiton in the southern Green Canyon area of the Gulf of Mexico. With primary development from three middle Miocene sands, it is one of BP’s largest fields in the deep water Gulf of Mexico. Discovered in 1998 and first production in 2007, Atlantis Field was developed in stages from a sub-sea drill center to a remote production facility. A second subsea drill center, centered on an early appraisal well, was connected in mid 2009. Drilling of water injection wells commenced in 2009 following initial dynamic data learning. Additional field development via appraisal drilling is planned for 2012, and two dynamically positioned semisubmersible rigs are currently active in the field. Located approximately 120 miles (190 km) south of Fourchon, Louisiana, Atlantis Field is a faulted, elongate asymmetric doubly-plunging anticline within the Atwater Fold Belt. Water depths range from 4500 to 7000 feet (1370 to 2070 m) across the field, influenced by the Sigsbee Escarpment, a region of steep sea floor dip created by a thick allochthonous salt complex that partially overlies the structure. Both the allochthonous salt and the significant sea floor relief create challenges in seismic imaging, field development, and have influenced the staged approach. The producing reservoirs are middle Miocene deep-water turbidites interpreted as a series of individual lobes in a submarine fan complex that were deposited in a relatively unconfined basin floor environment. Deformation of the reservoir commenced shortly after deposition and is dominated by the formation of the Atwater Fold Belt and culminated with the later partial burial of the structure by the thick allochthonous salt canopy. The reservoir was interpreted to be compartmentalized, based on the seismically defined faults, and these compartments were confirmed by static pressures. However, production data now indicate a greater reservoir compartmentalization beyond that initially defined. Data acquisition in new wells is targeted to understand further the reservoir deformation and stratigraphic complexity that negatively impacts permeability, acting as barriers or baffles to fluid flow.